System and method for real-time quality control for downhole logging devices

ABSTRACT

An illustrative embodiment of a method is disclosed for assessing image quality of a down hole formation image, the method comprising collecting acquisition system data from a plurality of sensors down hole; applying a set of rules to the acquisition system data to obtain an acquisition quality indicator; and presenting the acquisition quality indicator at a surface location. A system is disclosed for performing the method.

BACKGROUND

1. Field of the Invention

The invention generally relates to formation logging.

2. Background of the Related Art

Oil well logging has been known for many years and provides an oil andgas well driller with information about the particular earth formationbeing drilled. In conventional oil well logging, after a well has beendrilled, a probe known as a sonde is lowered into the borehole and usedto determine some characteristic of the formations which the well hastraversed. The probe is typically a hermetically sealed steel cylinderwhich hangs at the end of a long cable which gives mechanical support tothe sonde and provides power to instrumentation inside the sonde. Thecable also provides communication channels for sending information inthe form of data up to the surface. Thus, it is possible to measure someparameter of the earth's formations as a function of depth, that is,while the sonde is being pulled uphole through the borehole. Such“wireline” measurements are normally done in real time (however, thesemeasurements are taken long after the actual drilling of the boreholehas taken place).

A wireline sonde usually transmits energy into the formation surroundingthe borehole as well acting as a suitable receiver for detecting thesame energy returning from the formation to provide acquisition of aparameter of interest. As is well known in this art, these parameters ofinterest include but are not limited to electrical resistivity, acousticenergy, or nuclear measurements which directly or indirectly giveinformation on subsurface densities, reflectances, boundaries, fluidsand lithologies among many others.

Wireline formation evaluation tools (such as gamma ray density tools)have many drawbacks and disadvantages including loss of drilling time,the expense and delay involved in tripping the drillstring so as toenable the wireline tool to be lowered into the borehole and both thebuild up of a substantial mud cake and invasion of the formation by thedrilling fluids during the time period between drilling and takingmeasurements. An improvement over these prior art techniques is the artof measurement-while-drilling (MWD) in which many of the characteristicsof the formation are determined substantially contemporaneously with thedrilling of the borehole.

Measurement-while-drilling (MWD) either partly or totally eliminates thenecessity of interrupting the drilling operation to remove thedrillstring from the hole in order to make the necessary measurementsobtainable by wireline techniques. In addition to the ability to log thecharacteristics of the formation through which the drill bit is passing,this information on a real time basis provides substantial safety andlogistical advantages over wireline techniques for the drillingoperation. One potential problem with MWD logging tools is that themeasurements are typically made while the tool is rotating. Since themeasurements are made shortly after the drill bit has drilled theborehole, washouts are less of a problem than in wireline logging.Nevertheless, there can be some variations in the spacing between thelogging tool and the borehole wall (“standoff”) with azimuth. Nuclearmeasurements are particularly degraded by large standoffs due to thescattering produced by borehole fluids between the tool and theformation.

U.S. Pat. No. 5,397,893 to Minette, the contents of which are fullyincorporated herein by reference, teaches a method for analyzing datafrom a MWD formation evaluation logging tool which compensates forrotation of the logging tool (along with the rest of the drillstring)during measurement periods. The density measurement is combined with themeasurement from a borehole caliper, preferably an acoustic caliper. Theacoustic caliper continuously measures the standoff as the tool isrotating around the borehole. If the caliper is aligned with the densitysource and detectors, this gives a determination of the standoff infront of the detectors at any given time. This information is used toseparate the density data into a number of bins based on the amount ofstandoff. After a pre-set time interval, the density measurement canthen be made. The first step in this process is for short space (SS) andlong space (LS) densities to be calculated from the data in each bin.Then, these density measurements are combined in a manner that minimizesthe total error in the density calculation. This correction is appliedusing the “spine and ribs” algorithm to give a corrected density.

U.S. Pat. No. 6,584,837 to Kurkoski, fully incorporated by referenceherein, discloses a LWD density sensor that includes a gamma ray sourceand at least two NaI detectors spaced apart from the source fordetermining measurements indicative of the formation density. Amagnetometer on the drill collar measures the relative azimuth of theNaI detectors. An acoustic caliper is used for making standoffmeasurements of the NaI detectors. Measurements made by the detectorsare partitioned into spatial bins defined by standoff and azimuth.Within each azimuthal sector, the density measurements are compensatedfor standoff to provide a single density measurement for the sector. Theazimuthal sectors are combined in such a way as to provide a compensatedazimuthal geosteering density. The method of the invention may also beused with neutron porosity logging devices.

MWD instruments, in some cases, include a provision for sending at leastsome of the subsurface images and measurements acquired to recordingequipment at the earth's surface at the time the measurements are madeusing a telemetry system (i.e. MWD telemetry). One such telemetry systemmodulates the pressure of a drilling fluid pumped through the drillingassembly to drill the wellbore. The fluid pressure modulation telemetrysystems known in the art, however, are limited to transmitting data at arate of at most only a few bits per second. Because the volume of datameasured by the typical image-generating well logging instrument isrelatively large, at present, borehole images after an MWD instrument isremoved from the wellbore and the contents of an internal storagedevice, or memory, are retrieved, or in lower resolution while drilling.The images are available in real time and thus real time quality controlis provided in an illustrative embodiment.

Many types of well logging instruments have been adapted to makemeasurements which can be converted into a visual representation or“image” of the wall of a wellbore drilled through earth formations.Typical instruments for developing images of parameters of interestmeasurements include density measuring devices, electrical resistivitymeasuring devices, gamma images and acoustic reflectance/travel timemeasuring devices. These instruments measure a property of the earthformations proximate to the wall of the wellbore, or a related property,with respect to azimuthal direction, about a substantial portion of thecircumference of the wellbore. The values of the property measured arecorrelated to both their depth position in the wellbore and to theirazimuthal position with respect to some selected reference, such asgeographic north or the gravitationally uppermost side of the wellbore.A visual representation is then developed by presenting the values, withrespect to their depths and azimuthal orientations, for instance, usinga color or gray tone which corresponds to the value of the measuredproperty.

SUMMARY

An illustrative embodiment of a method is disclosed for assessing dataquality of a down hole formation image, the method comprising collectingdata from a plurality of sensors down hole and on the surface; applyinga set of rules to the acquired data to obtain an acquisition systemquality indicator; and presenting the indicator at a surface location. Asystem is disclosed for performing the method in real time.

BRIEF DESCRIPTION OF THE DRAWINGS

The illustrative embodiment and its advantages will be better understoodby referring to the following detailed description and the attacheddrawings in which:

FIG. 1 shows a schematic diagram of a drilling system having a drillstring that includes an apparatus according to the illustrativeembodiment;

FIG. 2 illustrates the sensor path for data acquisition by a downholeimaging tool while drilling;

FIG. 3 is a flow chart illustrating the overall organization of anillustrative embodiment;

FIG. 4 is a flow chart illustrating operations of the illustrativeembodiment;

FIG. 5 is a schematic diagram of a drilling system having a drill stringthat includes an apparatus according to the illustrative embodiment; and

FIG. 6-FIG. 15 are depictions of data structures embedded in a computerreadable medium containing data indicative of information useful inperforming the method and system of an illustrative embodiment.

DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

One method for transmitting image-generating measurements in pressuremodulation telemetry includes making resistivity measurements atpre-selected azimuthal orientations or azimuthal orientation intervals,and transmitting the acquired resistivity values to the surface throughthe pressure modulation telemetry.

In an illustrative embodiment, a method and system are disclosed forassessing data quality of a down hole device, such as a down holeformation logging tool, formation imaging tool or formation evaluationtool. The method comprising collecting imaging system data and loggingsystem data from a plurality of sensors down hole and up hole; applyinga set of rules to the imaging system data to obtain an image qualityindicator; and presenting the image quality indicator at the surfacelocation. In another embodiment the method further comprises providingcorrective action to adjust the data acquisition system indicated by theacquisition quality indicator. In another embodiment of the method, theimage system data further comprises electronic sensor data indicating atleast two items selected from the group consisting of downhole toolstatus, formation property, telemetry quality, bit position, and surveyquality. In another embodiment of the method, the rules are contained inan expert system. In another embodiment of the method, the rules arecontained in a neural network. In another embodiment inputs areprocessed by a software agent implementing an evaluation of the inputsto determine data quality using Bayesian statistics, principalcomponents, fuzzy logic, etc.

In another embodiment of the method, the set of rules is formed from aninitial training set of inputs and outputs, the method furthercomprising creating new rules by machine learning by tracking formationevaluation data, logging data, imaging system data and field serviceengineer corrective actions during operations. In another embodiment ofthe method, the imaging system data are dynamically weighted based onthe rules. In another embodiment of the method, the image qualityindicator is set to normal, which in a particular embodiment isindicated by a value of 0, when a down hole tool shows a guard electrodecurrent for a guard electrode which exceeds a defined limit and aformation resistivity data value indicates low resistivity in theformation else the image quality indicator is set to alert, which in aparticular embodiment is indicated by a 2, which when the down hole toolshows a current which exceeds a defined limit and the resistivity datavalue does not indicate low resistivity.

In another embodiment a system for assessing data quality of a down holeformation logging tool is disclosed, the system comprising a processorin data communication with a computer readable medium; and a computerprogram stored in the computer readable medium, the computer programcomprising instructions to collect acquisition system data from aplurality of sensors on a downhole device, such as a formationevaluation tool, down hole in a formation and uphole at a surfacelocation; instructions to apply a set of rules to system data to obtainan acquisition quality indicator; and instructions to present theacquisition quality indicator at the surface location. In anotherembodiment of the system, the computer program further comprisinginstructions to provide corrective action to adjust system and imagequality indicated by the acquisition quality indicator. In anotherembodiment of the system the acquisition system data further compriseselectronic sensor data indicating at least two items of data selectedfrom the group consisting of downhole tool status data, formationproperty data, telemetry quality data, bit position data, and surveyquality data. In another embodiment of the system the rules arecontained in an expert system. In another embodiment of the system therules are contained in a neural network. In another embodiment of thesystem the set of rules is formed from an initial training set of inputsand outputs, the computer program further comprising instructions tocreate new rules using machine learning by tracking acquisition systemdata and field service engineer corrective actions during imagingoperations. In another embodiment of the system the acquisition systemdata are dynamically weighted based on the rules. In another embodimentof the system the acquisition quality indicator is set to normal when adown hole tool shows a current which exceeds a defined limit and aformation resistivity data value indicates low resistivity in aformation else the acquisition quality indicator is set to alert whenthe down hole tool shows a current which exceeds a defined limit and theresistivity data value does not indicate low resistivity.

FIG. 1 shows a schematic diagram of a drilling system 100 having adownhole assembly containing a sensor system and the surface devicesaccording to one embodiment of present invention. As shown, the system100 includes a conventional derrick 111 erected on a derrick floor 112which supports a rotary table 114 that is rotated by a prime mover (notshown) at a desired rotational speed. A drill string 120 that includes adrill pipe section 122 extends downward from the rotary table 114 into aborehole 126. A drill bit 150 attached to the drill string downhole enddisintegrates the geological formations when it is rotated. The drillstring 120 is coupled to a drawworks 130 via a kelly joint 121, swivel128 and line 129 through a system of pulleys 127. During the drillingoperations, the drawworks 130 is operated to control the weight on bitand the rate of penetration of the drill string 120 into the borehole126. The operation of the drawworks is well known in the art and is thusnot described in detail herein.

During drilling operations a suitable drilling fluid (commonly referredto in the art as “mud”) 131 from a mud pit 132 is circulated underpressure through the drill string 120 by a mud pump 134. The drillingfluid 131 passes from the mud pump 134 into the drill string 120 via adesurger 136, fluid line 138 and the kelly joint 121. The drilling fluidis discharged at the borehole bottom 151 through an opening in the drillbit 150. The drilling fluid circulates uphole through the annular space127 between the drill string 120 and the borehole 126 and is dischargedinto the mud pit 132 via a return line 135. Preferably, a variety ofsensors (not shown) are appropriately deployed on the surface accordingto known methods in the art to provide information about variousdrilling-related parameters, such as fluid flow rate, weight on bit,hook load, etc.

A surface control unit 140 (which further includes an expert system orother software functionality such as an expert system or a neuralnetwork as shown in FIG. 4) receives signals from the downhole sensorsand devices via a sensor 143 placed in the fluid line 138 and processessuch signals according to programmed instructions provided to thesurface control unit. The surface control unit displays desired drillingparameters and other information on a display/monitor 142 whichinformation is utilized by an operator to control the drillingoperations. The surface control unit 140 contains a computer, memory forstoring data, data recorder and other peripherals. The surface controlunit 140 also includes models and processes data according to programmedinstructions and responds to user commands entered through a suitablemeans, such as a keyboard. The control unit 140 is preferably adapted toactivate alarms 144 when certain unsafe or undesirable operatingconditions occur.

In a particular embodiment, a drill motor or mud motor 155 coupled tothe drill bit 150 via a drive shaft (not shown) disposed in a bearingassembly 157 rotates the drill bit 150 when the drilling fluid 131 ispassed through the mud motor 155 under pressure. The bearing assembly157 supports the radial and axial forces of the drill bit, thedownthrust of the drill motor and the reactive upward loading from theapplied weight on bit. A stabilizer 158 coupled to the bearing assembly157 acts as a centralizer for the lowermost portion of the mud motorassembly.

In one embodiment of the system of present invention, the downholesubassembly 159 (also referred to as the bottom hole assembly or “BHA”)which contains the various sensors and MWD devices to provideinformation about the formation and downhole drilling parameters and themud motor, is coupled between the drill bit 150 and the drill pipe 122.The downhole assembly 159 preferably is modular in construction, in thatthe various devices are interconnected sections so that the individualsections may be replaced when desired.

Still referring to FIG. 1, the BHA also contains sensors and devices inaddition to the above-described sensors. Such devices may include adevice for measuring the formation resistivity near and/or in front ofthe drill bit, a gamma ray device for measuring the formation gamma rayintensity and devices for determining the inclination and azimuth of thedrill string. The formation resistivity measuring device 164 may becoupled above the lower kick-off subassembly 162 that provides signals,from which resistivity of the formation near or in front of the drillbit 150 is determined. A multiple propagation resistivity device (“MPR”)having one or more pairs of transmitting antennae 166 a and 166 b spacedfrom one or more pairs of receiving antennae 168 a and 168 b can beused. In operation, the transmitted electromagnetic waves are perturbedas they propagate through the formation surrounding the resistivitydevice 164. The receiving antennae 168 a and 168 b detect the perturbedwaves. Formation resistivity can be derived from the phase and amplitudeof the detected signals as well as the real and imaginary part of thesignal. The detected signals are processed by a downhole circuit that ispreferably placed in a housing 170 above the mud motor 155 andtransmitted to the surface control unit 140 using a suitable telemetrysystem 172. In addition to or instead of the propagation resistivitydevice, a suitable induction logging device or any other resistivitymeasurement device may be used to measure formation resistivity.

The inclinometer 174 and gamma ray device 176 may be placed along theresistivity measuring device 164 for respectively determining theinclination of the portion of the drill string near the drill bit 150and the formation gamma ray intensity. Any suitable inclinometer andgamma ray device, however, may be utilized for the purposes of thisinvention. In addition, an azimuth device (not shown), such as amagnetometer or a gyroscopic device, may be utilized to determine thedrill string azimuth. Such devices are known in the art and are, thus,not described in detail herein. In the above-described configuration,the mud motor 155 transfers power to the drill bit 150 via one or morehollow shafts that run through the BHA. The hollow shaft enables thedrilling fluid to pass from the mud motor 155 to the drill bit 150. Inan alternate embodiment of the drill string 120, the mud motor 155 maybe coupled below resistivity measuring device 164 or at any othersuitable place.

The drill string contains a modular sensor assembly, a motor assemblyand kick-off subs. In one embodiment, the sensor assembly may include aresistivity device, gamma ray device and inclinometer, all of which arein a common housing between the drill bit and the mud motor. Thedownhole assembly of the present invention may include a MWD sectionwhich contains a nuclear formation porosity measuring device, a nucleardensity device, an acoustic sensor system placed, and a formationtesting system above the mud motor 164 in the housing for providinginformation useful for evaluating and testing subsurface formationsalong borehole 126. A downhole processor may be used for processing thedata.

Wireline logging tools have been used successfully to produce subsurfaceimages. In an illustrative embodiment, for MWD applications,measurements made by the downhole sensors are sent to the surface usingthe telemetry system so that subsurface images and parameterdeterminations are available for real time applications such asgeosteering. In an illustrative embodiment, measurements and systemparameters sensed by the BHA are sent to the surface for real timeevaluation by a software function such as an expert system for apprisingthe field service engineer (FSE) at the surface of ongoing operations.The software function, which may also be implemented in hardware,monitors outputs from the BHA and presents a status indicator to the FSEas to whether the MWD system is normal, cautionary or on alert. In anillustrative embodiment, the MWD system provides for acquiring formationparameters based on specific BHA sensors, i.e., from any one of avariety of formation evaluation sensors, including a resistivity sensor,a density sensor, a porosity sensor, a micro-resistivity imaging sensor,a borehole televiewer, a gamma ray sensor and/or a caliper (acoustic ormechanical).

Turning now to FIG. 2, a borehole 126 is shown with six azimuthalsectors for simplicity. In an illustrative embodiment, the borehole isdivided into 120 sectors of 3 degrees each for total of 360 degrees. Oneof the sectors is labeled as 203. As noted, the use of 120 sectors isnot to be construed as a limitation of the invention and commonly, moreor less sectors may be used. As drilling progresses, a sensor on the BHAthat makes a measurement of a property of the borehole wall (or theadjacent formation) traces out a spiral path depicted by 205. The spiralpath will have a uniform pitch if the rate of penetration (ROP) of theBHA into the formation is uniform. In practice, the ROP may not beuniform.

In an illustrative embodiment, an image comprises three measuredquantities. The first is time or depth measured by an internal clock onthe BHA which may be processed in conjunction with a suitable depthmeasurement system. The second is a tool face angle measured by asuitable orientation device such as a magnetometer or a gyroscope. Thetool face angle can be referenced to magnetic north or to the high sideof the tool or any other suitable reference point. The difference of thetool face angles referenced to magnetic north and to the high side ofthe tool depends on tool azimuth and inclination as well as on magneticdip and can be measured separately or calculated from tool azimuth andinclination as well as magnetic dip measurements. Tool azimuth andinclination can be measured separately. In one embodiment of theinvention, they are measured by the directional sonde of ONTRAK™, atrademark of Baker Hughes Incorporated. Magnetic dip can be measured atthe surface or can be determined for instance by British GeologicalSurvey Global Geomagnetic Model (BGGM). A third quantity defining theimage is a formation property such as electrical resistivity, density,or porosity. The image itself consists of a matrix of formationevaluation measurements where row and column number of each matrix cellis characterized by time or depth and toolface angle, respectively. Thepenetration ΔL during one increment of the memory stamp T_(M) isindicated in FIG. 2 by 207. In an illustrative embodiment, the BHA datais transmitted from the downhole location via the telemetry system tothe surface and then reconstruct the image. The transmission of the datais done using a suitable telemetry channel such as mud pulse telemetrychannel 127. It should be noted that the BHA formation evaluation sensordo not have to make measurements during continued rotation of the BHA.

Turning now to FIG. 3, a flow chart illustrates the overall sequence ofoperations for the present invention applied to an imaging system. Atblock 221, the real-time imaging parameters are set. Block 223 refers tothe downhole operations. Block 225 broadly refers to operations relatingto the transmission of the data from the downhole location to thesurface location, and block 227 refers to operations at the surface.These broad categories are discussed next.

The set of parameters 221 determine the quality of the image received inreal-time. Programming the tool can be done while the tool is on surfaceor via downlink while the tool is downhole. The real time preset imagingparameters which are provided to the tool can include, but are notlimited to: (i) the number of rows and columns of the image; (ii) thetime resolution: this is the time covered by one single data row; (iii)the number of bits per pixel which is the number of bits with which themeasured formation evaluation values will be discretized (iv) the numberof telemetry words per time frame for one image block (v) the scalingmethod to be used; and (vi) the method of data block creation. Theparameters listed above are not meant to be inclusive, and in principle,there are other parameter sets possible which are related to theparameters in the list above.

The present invention also includes a mud pulse telemetry channel 172between the BHA and the surface control unit 140, which provides theability to alter at least a subset of the preset imaging parameters.With this technique, it is possible to change the options for real-timeimaging such as resolutions in time, tool face angle and resistivity.These options are defined by the set of imaging parameters. The imagingparameters can be changed while the drilling process is ongoing. Thiscan be very helpful for geosteering applications. Resetting ofparameters can be done manually via downlinks or automatically when themeasured data fulfill specific conditions based on application of rulesstored in the database 127 at the control unit 140. For example, thismay be done at regular time intervals, at regular depth intervals, whenspecific predefined depth is attained, when measured formationevaluation values show significant variation and/or when dips are foundby automatic dip detection algorithms as known in the art. The optionsfor real-time transmission can also be controlled by other formationevaluation measurement tools, e.g. bulk measurement tools.

Turning now to FIG. 4, in an illustrative embodiment, a set of functionsis performed as shown in FIG. 4. The order of execution in the flowchart of FIG. 4 is not dictated by FIG. 4 as any function shown in FIG.4 can be executed in any order with respect to the other functions inFIG. 4 as well as any function can be left out of execution altogether.

As shown in FIG. 4, in flow chart 400 an illustrative embodiment atblock 404 collects imaging system data (including but not limited todata sent from the BHA to the surface via telemetry channel 172, or fromup hole data sources) including but not limited to tool status, toolposition, telemetry system status and survey status. In block 406 anillustrative embodiment applies rules to the imaging system data toobtain a suggested corrective action and an imaging system qualityindicator. The inputs which include but are not limited to the imagingsystem data, are applied to a rule-based expert system, a rule-basedneural network or another rule-based software or hardware implementationthat operates on the imaging system data by applying rules to obtain asuggested corrective action and an imaging system quality indicator. Atblock 408, an illustrative embodiment presents the imaging systemquality indicator on a display at the surface. The imaging systemquality indicator can be displayed at the surface as a color-codedvertical bar to indicate the status of the imaging system, as discussedherein. In another illustrative embodiment the rule-based system istrained by an operator action such as the FSE taking corrective actionin adjusting or resetting the drilling system 100 based on the currentinputs from the imaging system data. In another illustrative embodiment,the rule-based system performs the corrective action by adjusting thedrilling system 100. Some examples of the corrective scenarios actionbased on imaging system data are discussed below. At block 410 anillustrative embodiment updates the rules based on the current imagingsystem data and the corrective action taken by the FSE or performed bythe rule-based system itself.

Turning now to FIG. 5, FIG. 5 is a schematic diagram of a drillingsystem having a drill string that includes an apparatus according to theillustrative embodiment. In an illustrative embodiment, the BHA 159sends imaging system data to the surface control unit 140 via the mudpulse telemetry channel 172. In an illustrative embodiment, real timequality control of formation image data is performed using an expertsystem, neural network or another rule-based control and analysissoftware on the surface in the control unit 140. The control unitfurther includes but is not limited to a processor 123, memory 125 anddata base 127. The memory is a computer readable medium containinginstructions that when executed by a computer are useful in performingfunction of the system and method of an illustrative embodiment. The BHAtransmits imaging system data, tool status and directional data 510 aswell as data indicating the quality of data transmission over the mudpulse telemetry channel 172.

The quality of imaging system data processed by the expert system isindicated by the transmitted real-time data 510. Quality depends onseveral factors evaluated by the expert system. One factor input to theexpert system is downhole tool status. Downhole tool problems can becategorized as either critical, e.g., complete image loss, ornon-critical, by the expert system rules. For example, the downhole toolmight choose to recover from a failure or suboptimal status indicatorfor which failure does not overly impair formation image quality. Asecond factor is the quality of the survey information that willdirectly influence image orientation and therefore any imageinterpretation based on the imaging data. The magnitude of the down holetool problem determines whether it can be accepted or not. A thirdfactor is the quality of the telemetry channel. Low bandwidth or failureof the telemetry will result in loss of image data or low qualityimages.

The surface system 148 or a down hole system sends directional data tothe control unit 140. The control system further provides detaileddiagnostics 401 for testing the drilling system, the BHA and the abilityof the BHA to perform imaging at an acceptable quality. The real timesystem status is displayed on display 142 to the FSE. As shown in FIG.6, the status can be displayed on the right side of the real time systemstatus display 142 as a single, color coded bar as red 144, yellow 146,or green 148. When clicking with the mouse on that bar, additionalinformation such as a suggested or pending expert system correctiveaction is provided as pop-up or in a text display. The quality controldata will also be made available on the database for display.

This following data structures shown in FIG. 7-FIG. 15 are illustrationsof data structures embedded in computer readable memory that containdata used by the expert system to assess imaging system quality andfurther demonstrate that the status is not only dependent on the toolstatus, but also on a number of different variables that are monitoredperiodically or continuously and/or simultaneously in order to get theoptimum image quality. To simplify this task for the FSE, a real-timequality control expert system was developed that monitors all relevantdata sources and analyses them in order to determine the overall systemstatus.

Turning now to FIG. 7, in an illustrative embodiment, as shown in FIG.7, the real-time system display 142 will display one of three states,normal, caution and alert. A normal or green status indicator indicatesthat all diagnostics are good, image quality is as expected. A cautionor yellow status indicator indicates that some non-critical diagnosticsare set, image might be affected. An alert or red status indicatorindicates that real-time system status is critical, no/bad imageacquired. As shown in FIG. 7, there are appropriate actions to be takenby the FSE running the real-time MWD system and the log analystinterpreting the image from the MWD system. If the status displayed onreal time display 142 is green 706, no action is needed by the fieldservice engineer (FSE) 702 and the log analyst 704 is assured that thereis good image quality that can be used for interpretation 706. If thestatus displayed on real time display 142 is yellow, the FSE shouldcheck the cause of the yellow caution from the system status 712 and ifpossible, return the system to green status. The log analyst is apprisedthat the image might be unusable and suggested or pending correctiveaction such as checking diagnostics, flagging the image as good or bad,and only to be used if the diagnostics indicate that the image is good710. If the system status displayed on real time display 142 is an alarmor red status the FSE should perform immediate trouble shooting 716 andthe log analyst is informed that the image should not be used forinterpretation 714. In an illustrative embodiment corrective action issuggested via display 142 or performed by the expert system or neuralnetwork. In another illustrative embodiment a script of correctionactions in output executed by the expert system or FSE.

Turning now to FIG. 8, the system status 800 is recorded as data storedin the data structure embedded in a computer readable medium for storingdata indicative of the system status. The system status, qualityindicator and input data can be adjusted or weighted based on the rules,for example, a system status of 1 can weighted adjusted to a status of 0or 2 based on an application of the rules to the input data. Forexample, in a particular illustrative embodiment, if sensor is powered802 the status is set to 2 804 pending further review and application ofthe rules on the status data by the expert system; and if the guardcurrent powering a guard electrode on the down hole tool thereby sendingan electromagnetic field into the formation, exceeds a predefined limit806, the status is set to 1, pending further review by and applicationof the rules on the status data by the expert system. The system statusis computed from several diagnostics with values 0-2 (0—green, 1—yellow,2—red), the value used is always the worst of all the input parameters(i.e., Imaging Quality Control Status (IQCS)=max (status 1, status 2, .. . , status N). The table below defines the diagnostics, providescorresponding status values, and the source. Some bits in status areassumed to be critical if they are zero, some if they are one howeverthe expert system will consider other imaging system data inputs tochoose a suitable status to display to the FSE on the real time display172. The following sections define the sources for the diagnostics aboveand how they are derived.

As shown in FIG. 9, the tool status is derived from the application of aset of rules applied to the tool status values and other system datainputs and stored in data structure 900. The tool status includesdownhole tool status via mud pulse telemetry 902. As shown in FIG. 9,based on the data in the data structure 900, an illustrative embodimentsets the real-time system status repeatedly use the latest value ofIQCS, until new value is determined by the expert system from theimaging and logging system data transmitted from the BHA 904.

As shown in FIG. 10, data structure 1000 contains data that indicateswhen a new directional information 1002 from downhole from the surfacesystem, the control unit 140 expert system 141 corrects down hole toolazimuth 1004 using magnetic to grid correction, subtracts surface systemazimuth from corrected DIT azimuth, subtracts surface system inclinationfrom DIT inclination, takes absolute values of inclination and azimuthdifference, and if one of the absolute values is more than predefinedlimit, sets defined status bit as 1, else sets defined status bit as 0.An illustrative embodiment uses this value of the status bit until newdownhole survey data arrive. If no directional information from DIT orsurface system surveys are present, the expert system stores missingvalues instead; does not display a curve; sets system status yellow; anddisplays a real time advisor message to suggest or perform correctiveaction to fix the problem.

As shown in FIG. 11, the complete system status data structure 1100contains data indicating flags provided by downhole tool status,directional survey status, and communication channel status. Anillustrative embodiment presents a plot or hard copy output of data fromthe downhole tool, referred to as a curve. The curves outlined in thetables below provide details to the FSE regarding possible causes, tofacilitate trouble shooting and corrective action, if system status isyellow or red. The curves also help a user make a detailed assessment ofthe image quality for interpretation/dip-picking when drilling systemstatus is yellow. The data is stored in the database 127 and displayed.

As shown in FIG. 12, data structure 1200 contains data indicatingconditions that enables an illustrative embodiment to assess effectsrelated to scaling differences of image frames an illustrativeembodiment examines current image block data 1202, takes minimum/maximumscaling values 1204 from transmitted image header and stores this datafor each image. In an illustrative embodiment this data is stored foreach image and is compared to other resistivity measurements.

As shown in FIG. 13, data structure 1300 contains data indicatingconditions that enables an illustrative embodiment to assess overallimage quality by checking telemetry band width by counting data wordstransmitted for the current image 1302 and storing and displaying thisdata for each image line 1304. As shown in FIG. 14, data structure 1400contains data indicating conditions that enables an illustrativeembodiment to assess overall image quality, an illustrative embodimentstores the amount of error correction used for the current image. Thedata structure includes fields for mud pulse telemetry (MPT) data streamquality 1402 and field for storing data indicative of the amount oferror correction currently used 1404 and a flag if a preset errorcorrection threshold is exceeded.

In one illustrative scenario in which the real time imaging systemassociated with the MWD tool BHA is inoperative as the drill bit ispicked up off the bottom of the borehole. In this case, the drill bit ispicked up off the bottom of the borehole, and mud circulation in theborehole is interrupted. When mud circulation is resumed an invaliddirectional survey is taken by the directional tool and sent to the BHAwhich reports the directional data to the surface control system. TheBHA uses the invalid directional survey data causing a rotated imageerror. In the present illustrative scenario, the real time qualitycontrol system 140 of the present illustrative embodiment monitors thedirectional data coming from the downhole tool through the telemetrychannel and from surface data sources, and determines that there is aproblem, thereby setting the real time quality control status to red oran alert indicator. The real time quality control system 140 alsomonitors other operational inputs from the imaging system and drillingsystem data, indicating for example, bit position. In an illustrativeembodiment, the expert system of the real time quality control systemapplies rules to the inputs and takes corrective action to remedy theproblem. In another illustrative embodiment, the expert system of thereal time quality control system applies rules to the inputs anddisplays recommended corrective action to remedy the problem. In anillustrative embodiment, the corrective action taken or displayed asrecommended is to cycle the mud pumps and initiate a new directionalsurvey so that the directional tool sends valid directional survey datato the BHA which relays valid image data to the surface. The real timequality control status displayed on the display 142 is set to green,indicating normal. In another illustrative scenario, the real timequality control system expert system monitors the mud pulse telemetryquality data and determines that telemetry data transmission has beeninterrupted for 10 seconds. Thus the displayed image data is incorrectdue to the data lost during the 10 second lapse in telemetrytransmission and a red alert status is displayed by the real timequality control system expert system. Appropriate corrective action istaken or recommended by the real time quality control system expertsystem. In another illustrative scenario, the real time quality controlexpert system determines that the error correction in the telemetrychannel is above an acceptable level, for example, above 10%.

Error correction algorithms are used including but not limited toReed-Solomon error correction which is an error-correcting code thatworks by oversampling a polynomial constructed from the data. Thepolynomial is evaluated at several points, and these values are sent orrecorded. By sampling the polynomial more often than is necessary, thepolynomial is over-determined. As long as “many” of the points arereceived correctly, the receiver can recover the original polynomialeven in the presence of a “few” bad points.

In an illustrative scenario, the real time quality control system sendscommands to restructure data transmission over the telemetry channelreducing the data transmission rate and the size of the data packetssent over the telemetry channel. In an illustrative embodiment the BHAsends images including drilling system data to the real time qualitycontrol system from which the real time quality control system performscorrective action or suggests corrective action. The BHA data caninclude but is not limited to data indicative of real time statusnormal, real time status cautionary, real time status critical, azimuth,inclination, time, some additional bulk measurements from other MWDtools, downhole imaging tool power on, memory status, internal toolcommunication status, magnetic or high side tool face reference,magnetometer status, getting of the image information from fullcircumference of borehole, absence of free memory space, measurementranges, mud pulse telemetry communication status, image's sector number,image's color depth, image counter, number of decoded words per image,error correction format.

In another particular illustrative embodiment, there are three maininputs. The first input data is made up of the data stream from the toolwhich contains the image data as well as diagnostic data, diagnosticdata could be ranges of the measurement, hardware indicators, i.e. areall electronics working to specs, for instance memory or magnetometerelectronics. The second set of input data is data from the mud pulsetelemetry (MPT) system. The software analyzes the data stream withrespect to its quality, i.e. are bits lost, how many bytes aretransmitted per image, have any errors occurred that can be corrected.The third set of inputs is made up of data from the surface system,which is particularly the survey information, i.e. well inclination andwell azimuth that is used. The system and method provide three systemstatus levels, good, bad, and intermediate. When system status is good(green) no action required by FSE. When the system status isintermediate (yellow) there is a possible problem, on which the FSEshould check. When the system status is red, or at an alert level whereimmediate corrective action is suggested, there is a system failure ofthe system, and immediate attention is suggested or required.

For every input from the down hole tool sent to the real time qualitycontrol system, including around 20 inputs in an illustrative system, arule, threshold and a severity are defined for each input individuallyand a rule defined for each input in the context of every other inputand input value. Corrective action is also suggested or provided byapplying the inputs to the rules in the expert system for various valuesfor each input. The severity is either intermediate or bad. In anotherparticular embodiment, if one input crosses its threshold, the systemstate is set to the respective severity of the input. For example, ifthere are ten inputs below their thresholds, one input at intermediateseverity and one that is bad, the overall state would be presumed badpending adjustment of the state by application of the rules in theexpert system or neural network.

Some of the rules operate on properties derived from imaging systemdata. For example, in a particular embodiment a survey problem isdetected as follows

1. Take the directional information that is used downhole (azimuth andinclination)

2. Take the official directional information (residing in the databaseon surface)

3. Take the difference of the two directional surveys

4. Set system status to cautionary (yellow) if this difference is largerthan 5°. In this case the system gets only a “cautionary” because animage with usable data is still being produced. If an error is detectedthe FSE or expert system “interacts” to determine the cause of theerror. This can mean two things. 1. The FSE or expert system will lookat the processing software (this software also contains the expertsystem) which shows all diagnostics and will display the cause. 2. TheFSE or expert system creates a detailed diagnostic plot that will showthe system status and the inputs. This allows an FSE or expert system tosee how the MWD system evolved in time and when and how it failed. Whenthe FSE or expert system determines the root cause of the error,corrective action is taken. This can mean several things:—Changing theparameters of the mud pulse telemetry, i.e. improving quality of thedata stream—Changing the parameters in the real-time acquisitionsoftware, for instance to make it less susceptible to transmissionerrors—Advising driller or client to take a specific action, i.e.restarting the tool, ignore certain parts of the acquired image.

The foregoing example is for purposes of example only and is notintended to limit the scope of the invention which is defined by thefollowing claims.

1. A method for assessing acquisition system status for a down hole device, the method comprising: collecting acquisition system data from a plurality of sensors down hole and up hole; applying a set of rules to the acquisition system data to obtain an acquisition quality indicator indicating quality of the acquisition data wherein the set of rules is formed from an initial training set of inputs and outputs; creating new rules by machine learning by tracking imaging system data and field service engineer corrective actions during imaging operations; and presenting the acquisition quality indicator at a surface location.
 2. The method of claim 1, further comprising: providing corrective action to adjust the acquisition system as indicated by the acquisition quality indicator.
 3. The method of claim 1, wherein the rules are contained in an expert system.
 4. The method of claim 1, wherein the rules are contained in a neural network.
 5. The method of claim 1, wherein the acquisition system data are dynamically weighted based on the rules.
 6. The method of claim 5, wherein the acquisition quality indicator is set to normal when a down hole tool shows a guard electrode current which exceeds a defined limit and a formation resistivity data value indicates low resistivity in the formation else the acquisition quality indicator is set to alert when the down hole tool shows the current which exceeds the defined limit and the resistivity data value does not indicate low formation resistivity.
 7. A system for assessing acquisition system quality of a down hole formation evaluation system, the system comprising: a processor in data communication with a non-transitory computer readable medium containing instructions stored therein for causing a computer to perform; a computer program stored in the non-transitory computer readable medium, the computer program comprising instructions to collect diagnostic system data from a plurality of sensors down hole; instructions to apply a set of rules to the acquisition system data to obtain an acquisition system quality indicator indicating quality of the acquisition data, wherein the set of rules is formed from an initial training set of inputs and outputs, the computer program further comprising instructions to create new rules by machine learning by tracking acquisition system data and field service engineer corrective actions during data acquisition operations; and instructions to present the acquisition system quality indicator at a surface location.
 8. The system of claim 7, the computer program further comprising instructions to provide corrective action to adjust the acquisition system quality indicated by the acquisition system quality indicator.
 9. The system of claim 7, wherein the rules are contained in an expert system.
 10. The system of claim 7, wherein the rules are contained in the computer program selected from the group consisting of a neural network computer program and a fuzzy logic computer program.
 11. The system of claim 7, wherein the acquisition system data are dynamically weighted based on the rules.
 12. The system of claim 11, wherein the image quality indicator is set to normal when a down hole tool shows a current consumption exceeding a limit and a formation resistivity data value indicates low resistivity in the formation else the data acquisition indicator is set to alert when the a down hole tool shows a current consumption exceeding a limit and the resistivity data value does not indicate low resistivity.
 13. A method for assessing acquisition system status for a down hole device, the method comprising: collecting acquisition system data from a plurality of sensors down hole and up hole; applying a set of rules to the acquisition system data to obtain an acquisition quality indicator indicating quality of the acquisition data, wherein the set of rules is formed from an initial training set of inputs and outputs; creating new rules by machine learning by tracking imaging system data and field service engineer corrective actions during imaging operations wherein the set of rules is formed from an initial training set of inputs and outputs; and presenting the acquisition quality indicator at a surface location.
 14. The method of claim 13 wherein the acquisition quality indicator is set to normal when a down hole tool shows a guard electrode current which exceeds a defined limit and a formation resistivity data value indicates low resistivity in the formation else the acquisition quality indicator is set to alert when the down hole tool shows the current which exceeds the defined limit and the resistivity data value does not indicate low formation resistivity.
 15. A system for assessing acquisition system quality of a down hole formation evaluation system, the system comprising: a processor in data communication with a non-transitory computer readable medium; a computer program stored in the non-transitory computer readable medium for causing a computer to perform a method, the computer program comprising instructions to collect diagnostic system data from a plurality of sensors down hole; instructions to apply a set of rules to the acquisition system data to obtain an acquisition system quality indicator indicating quality of the acquisition data; and instructions to present the acquisition system quality indicator at a surface location, wherein the set of rules is formed from an initial training set of inputs and outputs, the computer program further comprising instructions to create new rules by machine learning by tracking acquisition system data and field service engineer corrective actions during data acquisition operations.
 16. The system of claim 15, wherein the acquisition system data are dynamically weighted based on the rules. 